Designing for arc flash mitigation in solar photovoltaic systems

Rising solar capacity comes with rising risk. The challenge is mitigating that risk.

By Eric Loos, DLR Group January 5, 2018

Learning objectives:

  • Understand the needs and requirements for designing solar photovoltaic (PV) systems.
  • Review the codes, standards, and guidelines that dictate the design of PV systems.
  • Design electrical and power systems for arc flash mitigation in a PV system. 

Photovoltaic (PV) solar arrays introduce new challenges to arc flash analysis and mitigation within the energy industry, particularly within dc power distribution systems. As more large-scale arrays come online, it has become increasingly important for the industry to develop uniform design calculation standards, set proper maintenance procedures, and develop arc flash mitigation strategies. 

The solar industry is in a state of rapid growth. The National Solar Jobs Census states that one out of every 50 new jobs added in the U.S. in 2016 was created by the solar industry, representing 2% of all new jobs.

When an industry grows this quickly and begins to employ a large workforce with relatively few years of design, construction, or operating experience, clear guidelines are required to promote efficient facility performance and protect the safety of personnel (see Figure 1).

Over the course of the past 5 years, much has evolved in the large-scale PV sector. According to the Solar Energy Industries Association (SEIA), total solar capacity in the U.S. was 2 GW in 2012. By the end of 2016, total solar capacity had increased to nearly 15 GW—and more than 70% of this capacity came from utility-scale plants. Presently, it is estimated that 2,500 solar plants have come online or are currently under development, representing 41 GW of power. This trend is expected to continue as the cost of development falls (see Figure 2).

Article 690, Solar Photovoltaic (PV) Systems, has been in NFPA 70-2017: National Electrical Code (NEC) since 1984. Recognizing the growth of large-scale solar, the 2017 edition of the NEC dedicated an entire new article: Article 691, Large-Scale Photovoltaic (PV) Electric Power Production Facility, sets standards for safer installation practices within the industry.

Similar to other energy production facilities, solar plants must maximize energy production while maintaining a safe work environment. These facilities often have legal or contractual requirements to produce a specific amount of energy over the course of a defined period of time or to maintain a minimum capacity level during all operational hours. The inability to meet these requirements frequently has significant financial and operational impacts for all parties involved.

One of the greatest risks to any person maintaining an electrical production facility is arc flash. Arc flash risk is eliminated by de-energizing equipment when it is being worked on. However, it has become more common to maintain solar plants while they are still energized. This is not only due to operational requirements, but also because the dc side of the solar array will always be energized whenever it is exposed to solar radiation. This is during nearly all daytime hours, when maintenance is most often performed.

Understanding arc flash hazards

An arc flash hazard is defined by NFPA 70E-2018: Standard for Electrical Safety in the Workplace as “a dangerous condition associated with the possible release of energy caused by an electric arc.” This release of energy is caused by a line-to-line or line-to-ground fault in which energy is transformed into destructive elements, such as intense heat, light, and pressure. The energy released during these events can cause extreme sound and vaporization of metal. In short, it is an explosion. An arc flash can only occur in the presence of an energized source.

In a 2015 study, the Fire Protection Research Foundation found that 30,100 individuals were injured over the course of a 10-year period from electrical shock or arc flash across the U.S. The same study indicated that a substantial number of the injuries were the result of “work inappropriately performed on energized equipment.” Further research indicated that time pressures, supervisor demands, and a lack of clear organizational communications led these workers to take shortcuts that caused these events to occur. If proper protocols had been followed, these incidents could have been prevented entirely.

NFPA 70E’s Article 110.3(F) requires the implementation of an electrical safety program, which includes identification and risk assessment procedures, for systems with energized conductors operating at or above 50 V or where an electrical hazard exists. Furthermore, NFPA 70E Article 130.3(B)(1) requires an arc flash hazard analysis be performed. This analysis produces hazard warning labels for each piece of equipment likely to require examination, adjustment, servicing, or maintenance while energized, indicating the available incident energy and the corresponding working distance. Additionally, each label must indicate the required personnel protective equipment (PPE) that must be worn by service personnel. IEEE 1584-2002: Guide for Performing Arc Flash Hazard Calculations provides the industry’s standard guide for performing these calculations.

Unfortunately, there is minimal guidance in IEEE 1584 to quantify the arc flash hazard on the dc power distribution system of a PV array. Most electrical sources are at a constant voltage whereas the dc side of a solar array is a constant-current source and must be modeled accordingly. Most calculation strategies revolve around the conservative approach indicated in 2015 NFPA 70E Annex D.5. The annex includes two different calculation methods: the maximum power method and the detailed arcing current method.

Both methods have been questioned and investigated by industry experts, and the annex itself indicates that the maximum power method is conservatively high. In 2013, David Smith from Colorado State University wrote a detailed report regarding arc flash hazards in PV arrays in which he concluded that, while the detailed arcing current method produces a more realistic representation of dc arc flash hazards, “no consensus standard exists for calculating arc energies in dc systems.”

NFPA 70E does not exclude the use of alternative calculation methods. In the absence of clear and convincing scientific guidance or a recognized design standard, many designers have become reliant on outside studies and recommendations from industry leaders. Multiple publications on dc calculations have provided guidance in recent years. However, before determining any arc flash mitigation techniques, an arc flash hazard analysis must still be performed. The results of this analysis will guide designers and help them tailor the correct strategies to the needs of a specific project.

Competing demands

Maintaining and operating large-scale solar arrays requires a delicate balance between system availability, reliability, and integrity. These plants often have a power purchase agreement (PPA) or other contractual agreement in place that requires that energy be produced per specific terms, and if it is not, a financial penalty may be levied as compensation. While fulfilling these terms is an important factor, safety remains the highest priority.

Many utility solar plants are designed specifically to offset daily peak energy demands and/or reduce the costs to run auxiliary generation facilities during these peak times. The activation of these auxiliary generation plants can be a significant financial burden to most utilities due to the cost of the fuel required to cycle the systems on and off.

To effectively operate a PV system under these circumstances, the plant must first be correctly commissioned during construction and regularly maintained after it is turned over to its owner-operator. During the commissioning process, the array must be energized to some degree to test the system components and ensure the equipment is operating correctly and to specification. Typically, the dc side of the array is sequentially energized as the commissioning progresses, culminating in a full test of the array. Additionally, in many cases, the system is at least partially energized during maintenance to avoid downtime.

Arc flash mitigation strategies

Large-scale PV arrays typically involve medium voltage (15 kV and higher) ac collection systems and thousands of PV modules connected in series and in parallel at voltages equal to or higher than 1 kV. While the most important aspect of arc flash hazard prevention includes proper equipment labeling and defined maintenance procedures, there are many techniques that can be implemented during the design phase of a facility to reduce the arc flash hazard itself. The implementation of these techniques, combined with adequate and enforced safety procedures and protocols, can have a significant impact on the overall safety of personnel. For a PV array, it is most practical to approach mitigation techniques from ac and dc standpoints.

Mitigation: ac side. The ac side of a solar array can be handled by using conventional arc flash reduction strategies. Similar to programming a facility for functional needs, the proper arc flash reduction strategy starts with understanding how the owner-operator intends to use the plant. A designer should begin by asking several questions about how the facility is to be operated. A good question would be, who will be operating it and how many workers are expected to be onsite? The designer also should consider where the equipment will be placed. If the owner is a utility company, it is important to investigate its existing safety program and requirements, which in most cases are well documented. These items can help determine the correct arc flash energy reduction strategy, which may include one or more of the following: 

  • Specification of arc resistant switchgear.
  • Arc reduction maintenance controls.
  • Bus differential protection scheme.

Arc resistant switchgear is a strategy that is typically best suited for conditions in which the switchgear equipment is installed in a location consistently occupied by personnel or in a location where an arc flash event could cause additional harm to the surrounding environment. Arc resistant switchgear alone does not reduce arc flash energy. It is designed specifically to redirect the arc flash energy up and out the top of the enclosure, away from personnel and facility assets (see Figure 3).

This type of switchgear allows tasks, such as racking in or out of a power circuit breaker, to be performed with the equipment’s enclosure doors completely closed. This alone represents a significant increase in worker safety. The cost of arc resistant switchgear should be discussed with the owner during the design phase since the added expense may be easily justified.

One of the most effective methods for reducing arc flash energy is to adjust the trip time settings of the overcurrent protective devices feeding the array collection system. The adjustments of the trip settings will force the overcurrent devices to act quicker than normal in a fault condition, thus reducing the available incident energy to the area. There are multiple approaches for accomplishing this.

The arc flash reduction maintenance switch is one of the least expensive options and can be implemented in several ways (see Figure 4). The switch is an option on most power circuit breakers that, upon operation, will automatically adjust the device to operate faster than its programmed settings. This will reduce the available arc flash energy at the breaker location. The switch can be implemented in many ways including:

  • Specification of individual switches on each overcurrent device.
  • Combining multiple overcurrent device inputs to a single external switch that will send a signal to all associated breakers.
  • Integration of multiple external switches into the equipment doors of the switchgear housing, which would force the switch into operation whenever any equipment door is opened.

These strategies are not without their drawbacks. In all cases, human interaction is required. Like any mechanical device, switches can fail, thus reducing the overall reliability. The possibility of failure can increase in an outdoor environment, especially one with an abundance of dust. Additionally, when a maintenance switch is activated, the time settings of the associated overcurrent devices are reduced, which introduces the possibility of nuisance tripping if left activated after maintenance. Workers must remember to return the system to normal operation by ensuring switches are deactivated after maintenance is complete, or additional measures must be installed to supervise the status of the switch.

One way to eliminate any concerns about the reliability of an arc flash maintenance switch is to implement a bus differential protection scheme. This protection scheme is typically installed at the medium-voltage level and involves the use of a protective relay that monitors the incoming and outgoing current of the protected zone (the entire switchgear or a specific portion). Through the use of additional sets of current transformers (CTs), the relay monitors these currents; if the incoming and outgoing currents are not equal, a fault must exist and the relay will operate, reducing the available incident energy (see Figure 5).

Mitigation: dc side. While there are many available strategies to reduce arc flash energy on the ac side, the dc side currently has fewer options. On large-scale solar arrays, the modules are typically combined in parallel at multiple levels. In cases where larger central inverters (typically above 100 kW) are used, modules are paralleled at combiner boxes and then again at the inverter’s recombiner. As with panelboards in an ac distribution system that provide multiple circuits for loads, combiner boxes accept the multiple solar module strings on the dc side and combine the outputs in parallel for connection to the inverter. Most combiner boxes use an integrated disconnect switch to allow for local maintenance.

Larger central inverters will merge the combiner boxes using a built-in recombiner at high currents. The combined output of the module strings can lead to very high available arc flash incident energy at both the combiner boxes and at the recombiners. In the event of a fault on the dc side of the array, each combiner box will feed the fault to other combiner boxes through the associated inverter’s recombiner if the recombiner switch (or switches) are not disconnected. In most cases, the available incident energy at the central inverter’s recombiner is beyond the maximum limit and cannot be safely approached without de-energizing the equipment (see Figure 6).

In a typical 2 MW array using central inverters and standard 72-cell 340 W modules, the minimum required arc flash hazard PPE category throughout the dc side the array is three or higher. If the inverters are 500 kW or greater in size, no personnel will be able to safely approach the inverters recombiner while energized.

Because an array is energized during the day, the procedure to properly de-energize the dc side of an array for maintenance purposes is time-consuming. This is due to the combiner boxes being typically mounted far from one another. It can necessitate the temporary disconnection of a large portion of the array, depending on where the maintenance is required.

Most inverter manufacturers use fused recombiners and do not offer arc flash reduction mechanics. Options, such as an arc flash reduction switch, are not available because the internal fused switches cannot offer the trip timing adjustments required to reduce the available energy. For improved safety, the solar industry is looking to inverter manufacturers to offer dc arc flash mitigation options in the future.

Currently, the only available method to reduce arc flash hazard on the dc side is to decrease the number of parallel sources at any given point in the array. The most successful strategy is to use smaller string inverters in lieu of large central inverters. The use of string inverters typically eliminates the need for combiner boxes, as the inverter contains a combiner box that typically accepts from 15 to 24 strings. While some owner-operators do not wish to use a large quantity of inverters due to increased maintenance and an increased number of possible failure points, the use of string inverters will reduce the arc flash hazard in an array. By using a larger quantity of smaller inverters, less module strings will serve each inverter and the available fault current, thus fault energy is reduced. When compared to central inverters, in most cases, using these inverters can reduce the minimum required arc flash PPE category by two levels.

A modern large-scale array typically uses 1,500 V dc modules at approximately 340 W each. Using data from a typical 340 W module, and using the calculation method described by Shapiro and Radibratovic in Solar Pro Magazine, February/March 2014 issue, the graph in Figure 7 indicates the level of PPE required to approach a device as it relates to the number of parallel strings connected to a dc collection piece of equipment. The vertical line represents the difference between using standard 60 kW, 15-input-string inverters over central inverters. The graph represents only the energy supplied by the dc sources and does not include any ac contribution.

There is a substantial need in the industry to develop additional strategies to reduce the arc flash energy at the dc equipment in an array. Examples include:

  • Advances in dc combiner box design allowing remote operation via reclosing, which would permit combiners to be temporarily opened at a remote location (i.e., the central inverter) and then to reclose manually, minimizing the operational impact. This would provide a means to reduce the available incident energy at points throughout the array in an easily accessible manner.
  • Compartmentalizing the components inside equipment, such as switching mechanisms, that would normally be energized on the line side, physically removing them from the typical working area. This would eliminate their arc flash energy contribution in that area. This method has recently been introduced for ac disconnect switches.
  • Use of dc circuit breakers into combiners and recombiners at the source string level or at the combined output level to allow for a controllable protection scheme similar to ac components.

Promoting solar’s safety record and reputation

By combining reduction strategies during design with clear operational protocols, worker safety around solar arrays and overall reliability of a solar plant can be improved substantially.

Given the emergent nature of this industry, keeping safety incidents to a minimum is critical. Not only do unsafe conditions pose a risk to the solar sector’s growing workforce, but injuries also damage the industry’s reputation. These unfortunate events not only hurt workers, but can attract negative attention from the media, investors, policy-makers, and other stakeholders, which could potentially stall growth within a thriving industry that provides a clean and affordable energy alternative.

Case Study: Arc flash mitigation at a utility-scale plant

Recently, DLR Group supported a large-scale solar array located in the Midwest. The system was owned by a local utility and included a 15-kV ac collection system and multiple 1,850-kW central inverters. The array was the first for the utility, and it was intended to be a testing ground to gain insight into the operations of large-scale solar plants and their overall impact on utility infrastructure.

Because this was the inaugural array for the client, there was a great deal of discussion regarding the maintenance and commissioning. As with any utility company, safety is paramount. Because the energy source and system-equipment types were new to the personnel involved, training and development of maintenance procedures were needed.

The facility was installed on the site of an existing auxiliary generation plant. Due to the relatively low available fault current at the 15-kV interconnection point, it was decided that enhanced ac arc flash mitigation techniques were not required. The arc flash hazard analysis indicated that the required PPE levels at each of the ac equipment enclosures were within the acceptable limits for the utility because proper PPE is readily available at the existing auxiliary plant nearby.

While the ac arc flash levels were allowable to the utility, the dc side analysis indicated otherwise. Each inverter was supplied by approximately 360 parallel module strings at 1,000 V dc. Due to the large number of parallel strings at each inverter, the available incident energy at each inverter’s dc recombiner was calculated to be above the maximum level per NFPA 70E, and was therefore marked “unsafe.” To reduce the available energy at the inverters to a level that could be safely approached with PPE, the maximum allowable connected strings was calculated to be no greater than 96.

Combiner boxes were identified and cataloged with the number of strings being served. If the inverter’s recombiner ever requires service, the required number of combiner boxes would be disconnected temporarily. Because the inverter recombiners can feed other combiner boxes in the event of a fault, proper procedures were developed to recognize possible arc flash hazards based on the plant’s operating conditions at the time of maintenance or service.

Eric Loos is a senior electrical engineer and principal at DLR Group with more than 10 years of experience designing solar installations. He has worked on projects ranging from utility-scale plants to high-profile sports stadiums, as well as the 13-acre system on top of the Mandalay Bay Convention Center in Las Vegas.


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